Introduction
Heavy hydrocarbons in the form of petroleum deposits are distributed worldwide and the heavy oil reserves are measured in the hundreds of billions of recoverable barrels. Because of the relatively high viscosity, these crude deposits are essentially immobile and cannot be easily recovered by conventional primary and secondary means. The only economically viable means of oil recovery is by the addition of heat to the oil deposit, which significantly decreases the viscosity of the oil and allows the oil to flow from the formation into the producing wellbore. Today, the steam injection can be done in a continuous fashion in which steam displaces oil from hot zones to the producer wells or intermittently as in the so-called “huff and puff” or cyclic steam process in which the steam is injected into, and oil produced from the same well after a predetermined soaking period. Oil recovery by steam injection involves a combination of physical processes including, gravity drainage, steam drive and steam drag to move the heated oil from the upper oil zone into the lower producing zone.
The most significant oil recovery problem with heavy oil, tar sands and similar hydrocarbonaceous material is the extremely high viscosity of the native hydrocarbons. At reservoir conditions, the oil viscosity ranges from 10,000 cp at the low end of the range to 5,000,000 cp at the high end. The viscosity of steam at injection conditions is about 0.020 cp. Assuming similar rock permeability to both phases steam and oil, then the viscosity ratio provides a good measure of the flow transmissibility of the formation to each phase. Under the same pressure gradient, gaseous steam can therefore flow from 500,000 to 250,000,000 times easier through the material than the oil at reservoir conditions. Because of this viscosity ratio, it is imperative and critical to any recovery application that the steam be confined or limited to an area of the reservoir by a seal. This seal can be physical, hydraulic or pneumatic and essentially must provide a physical situation which guarantees no-flow of any fluid across an interface. This can be implemented by several means. Without this “barrier” the steam will bypass, overrun, circumvent, detour around the cold viscous formation and move to the producer wellbore. This invention addresses and resolves this major obstructive element in heavy oil recovery.
Because of the extremely high viscosity of the heavy hydrocarbon in-situ, it is difficult if not impossible to physically move the displaced oil from the hot mobile location, through the cold porous rock formation to the producing wellbores. By implementing the novel processes which are taught in this application by this invention, especially the development of a hot annular vertical communicative zone of reduced viscosity and increased transmissibility, the oilfield operator can see improved performance, lower costs, better oilfield management, and allow for efficient and orderly development of petroleum resources.
In one embodiment of the invention, improvements have been made in enhancing the contact of the steam with the native heavy oil by the introduction of horizontal well technology, which allows greater recovery than with the customary vertical wells. This current invention provides a further extension of the horizontal technology in which a novel drilling methodology is applied to the drilling effort to allow wells of much larger lateral extent, potentially larger diameters and thereby more efficient recovery systems.
THIS NEW INVENTION provides an improvement in the oil recovery method whereby the operator drills a typical vertical well which is drilled from the surface down to the producing formation and continues past the pay zone into the under-burden. A cavity is developed below the pay zone by under-reaming the vertical wellbore to form a collection cavity. This under-reaming can be made up to 8 or 9 feet in diameter using standard reaming technology and tools used in the oil and gas industry today. The volumetric size of the cavity will be sized according to the required and expected oil production from each well.
This cavity is an additional implementation into which the hot displaced oil is allowed to drain from the heated zones into this collection cavity. Standard pumping equipment lifts the produced oil from the collection cavity. The techniques proposed herein uses a combination of drilling activities that are known separately and distinctly in the industry, but have not yet been utilized in this integrated manner shown in this new invention.
Prior Art
Various methods and processes have been disclosed for recovery of oil and gas by using horizontal wells. There have been various approaches utilized with vertical wellbores, to heat the reservoirs by injection of fluids and also to create a combustion front in the reservoir to displace the insitu oil from the injection wellbore to the production wellbore.
U.S. Pat. No. 3,986,557 claims a method using a horizontal well with two wellheads that can inject steam into a tar sand formation mobilizing the tar in the sands. In this patent, during the injection of the steam it is hoped that the steam will enter the formation and not continue directly down the open wellbore and back to the surface of the opposite wellhead. It is technically difficult to visualize the steam entering a cold formation with extremely highly viscous oil, while a completely open wellbore is available for fluid flow away from the formation. Furthermore, U.S. Pat. No. 3,986,557 teaches that the steam is simultaneously injected through perforations into the cold bitumen formation while hot oil is flowing in the opposite direction against the invading high pressure steam through the same perforations through the rock pore structure. This situation is not only physically impossible but it thermodynamically impossible for the fluid to flow against the pressure gradient.
U.S. Pat. No. 3,994,341 teaches a vertical closed loop system inside the wellbore tubulars in which a vertical wellbore is used to generate a vertical circulation of hot fluids which heat the wellbore and nearby formation. Hot fluids and drive fluids are injected into upper perforations which allow the driven oil to be produced from the bottom of the formation after being driven towards the bottom by the drive fluid.
U.S. Pat. No. 4,034,812 describes a cyclic injection process where a single wellbore is drilled into an unconsolidated mineral formation and steam is injected into the formation for a period of time to heat the viscous petroleum near the well. This causes the unconsolidated mineral sand grains to settle to the bottom of the heated zone in a cavity and the oil to move to the top of the zone.
U.S. Pat. No. 4,037,658 teaches the use of two vertical wells connected by a cased horizontal shaft or “hole” with a flange in the vertical well. This type of downhole flange connection is extremely difficult if not impossible to implement in current oilfield practice. Two types of fluids are used in this patent, one inside the horizontal shaft as a heater fluid and one in the formation as a drive fluid. Both fluids are injected either intermittently or simultaneously from the surface wellheads.
Butler et al in U.S. Pat. No. 4,116,275 use a single horizontal wellbore with multiple tubular strings internal to the largest wellbore for steam recovery of oil. Steam was injected via the annulus and after a soak period, the oil is produced from the inner tubing strings.
U.S. Pat. No. 4,445,574 teaches the drilling of a single well with two wellheads. This well is perforated in the horizontal section and a working fluid is injected into the wellbore to produce a mixture of reservoir oil and injected working fluid. Similar to the U.S. Pat. No. 3,986,557 patent it is difficult from a hydraulic point of view to visualize and contemplate the working fluid entering the formation in a vertical direction while an open wellbore is available for fluid flow horizontally and vertically out the distal end of this wellbore.
U.S. Pat. No. 4,532,986 teaches an extremely complex dual well system including a horizontal wellbore and a connecting vertical wellbore which is drilled to intersect the horizontal well. The vertical well contains a massively complex moveable diverter system with cables and pulleys attached to the two separate wellheads to allow the injection of steam. This system is used to inject steam from the vertical wellhead into the horizontal wellbore cyclically and sequentially while the oil is produced from the wellhead at the surface end of the horizontal well.
Huang in U.S. Pat. No. 4,700,779 describes a plurality of parallel horizontal wells used in steam recovery in which steam is injected into the odd numbered wells and oil is produced in the even numbered wells. Fluid displacement in the reservoir occurs in a planar fashion.
U.S. Pat. No. 5,167,280 teaches single concentric horizontal wellbores in the hydrocarbon formation into which a diffusible solvent is injected from the distal end to effect production of lowered viscosity oil backwards at the distal end of the concentric wellbore annulus.
U.S. Pat. No. 5,215,149 Lu, uses a single wellbore with concentric injection and production tubular strings in which the injection is performed through the annulus and production occurs in the inner tubular string, which is separated by a packer. This packer limits the movement of the injected fluids laterally along the axis of the wellbores. In this invention, the perforations are made only on the top portion of the annular region of the horizontal well. Similarly, the production zone beyond the packer is made on the upper surface only of the annular region. These perforated zones are fixed at the time of well completion and remain the same throughout the life of the oil recovery process.
Balton in U.S. Pat. No. 5,402,851 teaches a method wherein multiple horizontal wells are drilled to intersect or terminate in close proximity a vertical well bore. The vertical wellbore is used to actually produce the reservoir fluids. The horizontal wellbore provides the conduits, which direct the fluids to the vertical producing wellbore.
U.S. Pat. No. 5,626,193 by Nzekwu et al disclose a single horizontal well with multiple tubing elements inside the major wellbore. This horizontal well is used to provide gravity drainage in a steam assisted heavy oil recovery process. This invention allows a central injector tube to inject steam and then the heated produced fluids are produced backwards through the annular region of the same wellbore beginning at the farthest or distal end of the horizontal wellbore. The oil is then lifted by a pump. This invention shows a process where the input and output elements are the same single wellbore at the surface.
U.S. Pat. No. 5,655,605 attempts to use two wellbores sequentially drilled from the surface some distance apart and then to have these horizontal wellbore segments intersect each other to form a continuous wellbore with two surface wellheads. This technology while theoretically possible is operationally difficult to hit such a small underground target, i.e the axial cross-section of a typical 8-inch wellbore using a horizontal penetrating drill bit. It further teaches the use of the horizontal section of these intersecting wellbores to collect oil produced from the formation through which the horizontal section penetrates. Oil production from the native formation is driven by an induced pressure drop in the collection zone by a set of valves or a pumping system which is designed into the internal concentric tubing of this invention. The U.S. Pat. No. 5,655,605 also describes a heating mechanism to lower the viscosity of the produced oil inside the collection horizontal section by circulating steam or other fluid through an additional central tubing located inside the horizontal section. At no time does the steam or other hot fluid actually contact the oil formation where viscosity lowering by sensible and latent heat transfer is needed to allow oil production to occur.
Patent application 20050045325 describes a recovery mechanism for heavy oil hydrocarbons in which a pair of wells is used. A vertical injector well is horizontally separated from a vertical production well. The hot fluid, steam or air is injected into the bottom portion of the injector and is expected to displace the very viscous immobile oil from the cold reservoir and push this hot oil through the cold oil saturated formation eventually to the producer. The invention expects oil flow to occur by drilling a web or radial channels from the injector to the producer. It is inconceivable that viscous cold oil, or even lower viscosity hot oil will preferably flow along these channels while extremely low viscosity high-pressure steam will flow through the cold formation. Flow in porous media dictates that hot, saturated steam will completely bypass cold viscous oil and the process will be a quick steam recycle process from injector to producer.
U.S. Pat. No. 6,708,764 provides a description of an undulating well bore. The undulating well bore includes at least one inclining portion drilled through the subterranean zone at an inclination sloping toward an upper boundary of the single layer of subterranean deposits and at least one declining portion drilled through the subterranean zone at a declination sloping toward a lower boundary of the single layer of subterranean deposits. This embodiment looks like a waveform situated in the rock formation.
U.S. Pat. No. 6,725,922 utilizes a plurality of horizontal wells to drain a formation in which a second set of horizontal wells are drilled from and connected to the first group of horizontal wells. These wells from a dendritic pattern arrangement to drain the oil formation.
U.S. Pat. No. 6,729,394 proposes a method of producing from a subterranean formation through a network of separate wellbores located within the formation in which one or more of these wells is a horizontal wellbore, however not intersecting the other well but in fluid contact through the reservoir formation with the other well or wells.
U.S. Pat. No. 6,948,563 illustrates that increases in permeability may result from a reduction of mass of the heated portion due to vaporization of water, removal of hydrocarbons, and/or creation of fractures. In this manner, fluids may more easily flow through the heated portion
U.S. Pat. Nos. 6,951,247, 6,929,067, 6,923,257, 6,918,443, 6,932,155, 6,929,067, 6,902,004, 6,880,633, 20050051327, 20040211569 by various inventors and assigned to Shell Oil Company have provided a very exhaustive analysis of the oil shale recovery process using a plurality of downhole heaters in various configurations. These patents utilize a massive heat source to process and pyrolize the oil shale insitu and then to produce the oil shale products by a myriad of wellbore configurations. These patents teach a variety of combustors with different geometric shapes one of which is a horizontal combustor system which has two entry points on the surface of the ground, however the hydrocarbon production mechanism is considerably different from those proposed herein by this subject invention.
U.S. Pat. No. 6,953,087 by Shell, shows that heating of the hydrocarbon formation increases rock permeability and porosity. This heating also decreases water saturation by vaporizing the interstitial water. The combination of these changes increases the fluid transmissibility of the formation rock in the heated region.
The Society of Petroleum Engineers Ref. 1, SPE paper 20017 teaches a computer simulation of a displacement process using a concentric wellbore system of three wellbore elements and complex packers in which steam is injected in a vertical wellbore similar to that in the U.S. Pat. No. 3,994,341. Simulated steam injection occurs through one tubing string and circulates in the wellbore from just above the bottom packer to the injection perforations near the top of the tar sand. This perforations near the top of the tar sand. This circulating steam turns the wellbore into a hot pipe which heats an annulus of tar sand and provides communication between the steam injection perforations near the top of the tar sand and the fluid production perforations near the bottom of the tar sand. This process requires 7 years to increase oil production from 20 BOPD to 70 BOPD.
Paper 37115 describes a single-well technology applied in the oil industry which uses a dual stream well with tubing and annulus: steam is injected into the tubing and fluid is produced from the annulus. The tubing is insulated to reduce heat losses to the annulus. This technology tries to increase the quality of steam discharged to the annulus, while avoiding high temperatures and liquid flashing at the heel of the wellbore.
SPE paper 50429 presents an experimental horizontal well where the horizontal well technology was used to replace ten vertical injection wells with a single horizontal well with limited entry. The limited-entry perforations enabled steam to be targeted at the cold regions of the reservoir.
SPE paper 50941 presents the “Vapex” process which involves injection of vaporized hydrocarbon solvents into heavy oil and bitumen reservoirs; the solvent-diluted oil drains by gravity to a separate and different horizontal production well or another vertical well.
SPE paper 53687 shows the production results during the first year of a thermal stimulation using dual and parallel horizontal wells using the SAGD technology in Venezuela.
SPE paper 75137 describes a THAI—‘Toe-to-Heel Air Injection’ system involving a short-distance displacement process, that tries to achieve high recovery efficiency by virtue of its stable operation and ability to produce mobilized oil directly into an active section of the horizontal producer well, just ahead of the combustion front. Air is injected via a separate vertical or a separate horizontal wellbore into the formation at the toe end of different horizontal producer well and the combustion front moves along the axis of the producer well.
SPE paper 78131 published an engineering analysis of thermal simulation of wellbore in oil fields in western Canada and California, U.S.A.
SPE paper 92685 describes U-tube well technology in which two separate wellbores are drilled and then connected to form a single wellbore. The U-tube system was demonstrated as a means of circumventing hostile surface conditions by drilling under these physical obstacles.
Reference 2 shows conclusively that the gravity drainage effect is the most critical factor in oil recovery in heavy oil systems undergoing displacement by steam.
Very few of these prior art systems have been used in the industry with any success because of their technical complexity, operational difficulties, and being physically impossible to implement or being extremely uneconomical systems.
For example, in U.S. Pat. No. 3,994,341, this embodiment which although on the surface resembles the invention herein differs significantly since, the U.S. Pat. No. 3,994,341 forms a vertical passage way only by circulating a hot fluid in the wellbore tubulars to heat the nearby formation, the U.S. Pat. No. 3,994,341 patent claims the drive fluid promotes the flow of the oil by vertical displacement downwards to the producing perforations at the bottom, the U.S. Pat. No. 3,994,341 teaches the production perforations are set at the bottom of the vertical formation, a distance which can be several hundred feet. In this U.S. Pat. No. 3,994,341 embodiment, since no control mechanism like a back pressure system or pressure control system is taught, it is obvious that the high pressure drive steam, usually at several hundred psi, will preferentially flow down the vertical passageway immediately on injection and bypass the cold formation with its highly viscous crude and extremely low transmissibility. Secondly, the large distance between the top of the formation and the bottom of the formation will cause condensation of the drive steam allowing essentially hot water to be produced at the bottom with low quality steam, both fluids being re-circulated back to the surface. In addition, the mechanism to heat the near wellbore can only be based on conductive heat transfer through the steel casing. There is ineffective heat transfer since there is no direct steam contact with the formation rock in which latent heat transfer to formation fluids and rock can occur, this latent heat being the major heat transport system. The U.S. Pat. No. 3,994,341 process is incapable of delivering sufficient heat in a reasonable time to heat the formation sufficiently to lower the viscosity of the oil, raise the porosity and permeability of the formation as taught in the present patent application.
There is a long felt need in the industry for a means of moving the heated low viscosity crude oil that has been contacted by the steam in the steam zone to a place or location where it can be produced without having to move it through a cold heavily viscous oil saturated formation. This problem has continued to baffle the contemporary and prior art with possibly the only exception being the SAGD patent which uses two horizontal wells closely juxtaposed in a vertical plane. Even this SAGD approach has inherent difficulties in initiating the hot oil flow between the two wellbores. Trying to push the hot oil through a cold formation is an intractable proposition. The subject invention offers a solution to this need and provides the mechanism by which the solution can be implemented using conventional equipment and procedures.
Shortcomings of prior art can be related a combination of effects. These include;                (1) the inability of the process to inject the hot fluid into cold highly viscous oil saturated formations having a limited conductivity where the hydrocarbon viscosities are in excess of 106 cp. With this viscosity the liquid is essentially immobile at reservoir temperature.        (2) the inability to overcome the viscosity difference effect, wherein the viscosity of steam is less than 0.020 cp under the reservoir conditions which makes the flow of steam through porous media 5,000,000 times easier than cold oil having a high viscosity of 100,000 cp. This flow ratio is based directly on the viscosity ratios of 100,000/.02;        (3) the inability of the prior methods to prevent bypass of injected fluid directly from the injector source towards the producing sink;        (4) the inability of the prior methods to form and maintain a viable communication zone from the steam zone or chamber to the producing sink while simultaneously preventing bypass and early breakthrough of steam;        (5) the inability of the prior processes to effectively utilize the gravity drainage effects created by the low density of the hot steam compared to the high density of condensed water and hot oil;        (6) the inability of the prior processes to heat the formation effectively by physical contact between the steam and the rock formation such that latent heat, the major source of steam heat energy, can be transferred to the rock and hydrocarbons efficiently;        (7) The requirement of long lead times of months to years of hot fluid injection, before there is any measurable production response of the displaced oil in the production wells;        (8) The inability of the existing technology to maintain and sustain oil production rates when applied to large patterns of several wells;        (9) Finally the use of overly complex equipment of questionable operational effectiveness to implement the process in the field.        